COMMISSIONING OF INNERGEX 31ST HYDRO FACILITY
ACQUISITION OF THREE WIND FARMS IN FRANCE FOR 119.5 MW
- Revenues increased 25% to $109.5
million compared with the same period last year.
- Adjusted EBITDA rose 29% to $85.9
million compared with the same period last year.
- Innergex and Desjardins Group Pension Plan completed the
acquisition of the Rougemont 1-2
and Vaite wind facilities in France with a total aggregate installed
capacity of 119.5 MW.
- In British Columbia, the 25.3
MW Boulder Creek hydroelectric facility began commercial operation
on May 16, 2017.
(All amounts are in Canadian dollars, except as noted.)
LONGUEUIL, QC, Aug. 3,
2017 /CNW Telbec/ - Innergex Renewable Energy Inc.
(TSX: INE) ("Innergex" or the "Corporation") today released
its operating and financial results for the second quarter ended
June 30, 2017.
"The last quarter was exhilarating for the Innergex team with
the commissioning of our 31st hydro facility in Canada, the completion of a 119.5 MW
acquisition and the signing of a final agreement to purchase two
additional wind farms in France,"
said Michel Letellier, President and Chief Executive Officer
of the Corporation. "We deliver on our promise to pursue growth in
Canada and internationally both by
acquiring and developing projects."
"Our second quarter results were impacted by lower production
than the long-term average ("LTA") mainly due to challenging
post-commissioning activities at Upper Lillooet River, Boulder
Creek and Mesgi'g Ugju's'n facilities. Engineering and operational
adjustments are being made to rectify the situation and we should
reach full potential in the coming months. Our current geographic
diversification and the complementarity of hydroelectric, wind and
solar power generation nonetheless mitigated the impact of the
lower production on our results and should continue to benefit us
in the long-term," he added.
OPERATING RESULTS
|
|
|
Amounts shown are
in thousands of Canadian dollars
except as noted otherwise.
|
Three months ended
June 30
|
Six months ended
June 30
|
2017
|
2016
|
2017
|
2016
|
Power generated
(MWh)
|
1,322,781
|
|
1,176,451
|
|
2,045,053
|
|
1,840,838
|
|
Long-term average
(MWh)
|
1,437,100
|
|
1,045,265
|
|
2,257,734
|
|
1,602,286
|
|
Revenues
|
109,530
|
|
87,784
|
|
184,056
|
|
150,265
|
|
Adjusted
EBITDA1
|
85,920
|
|
66,863
|
|
136,861
|
|
114,542
|
|
Net
earnings
|
14,100
|
|
15,677
|
|
11,766
|
|
22,873
|
|
Net earnings, $ per
share – basic and diluted
|
0.12
|
|
0.12
|
|
0.13
|
|
0.19
|
|
|
|
|
|
|
|
|
|
|
|
Free Cash
Flow1
|
|
|
75,888
|
|
78,939
|
|
Payout
Ratio1
|
|
|
93
|
%
|
84
|
%
|
1 Please
refer to the Non-IFRS Measures Disclaimer for the definition of
Adjusted EBITDA, Free Cash Flow and Payout Ratio.
|
Electricity Production
During the three-month period ended June 30, 2017, the
Corporation's facilities produced 1,323 GWh of electricity or
92% of the LTA of 1,437 GWh. Overall, the hydroelectric
facilities produced 95% of their LTA due mainly to lower production
from post-commissioning activities at the Upper Lillooet River and
Boulder Creek facilities during the quarter, partly offset by
above-average water flows in Quebec and Ontario. The wind farms produced 84% of their
LTA due to lower production from post-commissioning activities at
the Mesgi'g Ugju's'n facility and to the below-average wind regimes
in Quebec and France. The solar farm produced 101% of its
LTA due to an average solar regime. The 12 % production increase
over the same period last year is due mainly to the contribution of
the recently commissioned or acquired facilities, which was partly
offset by lower production at most of our British Columbia hydro facilities and to lower
production at our Quebec wind
farms.
During the six-month period ended June 30, 2017, the
Corporation's facilities produced 2,045 GWh of electricity or
91% of the LTA of 2,258 GWh. Overall, the hydroelectric
facilities produced 94% of their LTA due mainly to lower production
from post-commissioning activities at the Upper Lillooet River and
Boulder Creek facilities during the period and below-average water
flows in British Columbia, partly
offset by above-average water flows in Quebec and Ontario. The wind farms produced 84% of their
LTA due to lower production from post-commissioning activities at
the Mesgi'g Ugju's'n facility and below-average wind regimes in
Quebec and France. The solar farm produced 104% of its
LTA due to an above-average solar regime. The 11% production
increase over the same period last year is due mainly to the
contribution of the recently commissioned or acquired facilities,
which was partly offset by lower production at most of our
British Columbia hydro facilities
and to lower production at our Quebec wind farms.
Revenues
For the three-month period ended June 30, 2017, the
Corporation recorded revenues of $109.5
million, compared with $87.8 million for three-month period ended
June 30, 2016. This 25% increase is
attributable mainly to the contribution of the Mesgi'g Ugju's'n
wind farm and Big Silver Creek hydro facility commissioned in 2016
and of the Upper Lillooet River and Boulder Creek hydro facilities
commissioned in 2017 as well as to the acquisition of the Montjean,
Theil-Rabier, Yonne, Rougemont 1-2
and Vaite wind facilities in France in 2016 and 2017, which was partly
offset by lower production at our British
Columbia hydro facilities and at our Quebec wind farms.
For the six-month period ended June 30, 2017, the
Corporation recorded revenues of $184.1
million, compared with $150.3 million for six-month period ended
June 30, 2016. This 22% increase is
attributable mainly to the facilities commissioned in 2016 and 2017
and the acquisitions of wind facilities in France in 2016 and 2017, which was partly
offset by lower production at most of our British Columbia hydro facilities and at our
Quebec wind farms.
Adjusted EBITDA
For the three- and six-month periods ended June 30, 2017,
the Corporation recorded Adjusted EBITDA of $85.9 million and $136.9 million, respectively compared with
$66.9 million and $114.5 million for the same periods last
year. These increases of 29% for three-month period and 19% for the
six-month period are due mainly to the production and revenues from
new facilities, partly offset by higher operating expenses and
general and administrative expenses. The three-month period
Adjusted EBITDA was also positively impacted by lower prospective
expenses. The Adjusted EBITDA Margin increased from 76.2% to 78.4%
for the quarter due mainly to lower prospective expenses and an
increase in revenues net of operating expenses. The Adjusted EBITDA
Margin decreased from 76.2% to 74.4% for the six-month period due
mainly to the payment related to water rights for 2011 and 2012 in
British Columbia made in the first
quarter of 2017.
Net Earnings
For the three-month period ended June 30, 2017, the
Corporation recorded net earnings of $14.1
million (basic and diluted net earnings of $0.12 per share), compared with net earnings of
$15.7 million (basic and diluted net
earnings of $0.12 per share) in 2016.
The $1.6 million decrease in net
earnings can be explained mainly by this year's below-average
production compared with last year's above-average production,
which explains the net earnings decrease as opposed to the increase
in revenues. As a result, the $14.5
million increase in finance costs, the $9.8 million increase in depreciation and
amortization related primarily to the greater number of operating
facilities and the $2.6 million
change in the unrealized net loss on derivative financial
instruments were only partly offset by the $19.1 million increase in Adjusted EBITDA, the
$4.7 million decrease in income
tax expenses and the $1.3 million increase in share of earnings
of joint ventures.
For the six-month period ended June 30, 2017, the
Corporation recorded net earnings of $11.8 million (basic and diluted net
earnings of $0.13 per share),
compared with net earnings of $22.9 million (basic and diluted net
earnings of $0.19 per share) in 2016.
The $11.1 million decrease in
net earnings can be explained mainly by this year's below-average
production compared with last year's above-average production,
which explains the decrease in net earnings as opposed to the
increase in revenues. As a result, the $24.3 million increase in finance costs and
the $20.0 million increase in
depreciation and amortization were only partly offset by the
$22.3 million increase in
Adjusted EBITDA, the $6.8 million decrease in income tax expenses
and the $2.5 million share of
earnings of joint ventures.
Free Cash Flow and Payout Ratio
For the trailing twelve-month period ended June 30, 2017,
the Corporation generated Free Cash Flow of $75.9 million, compared with $78.9 million for the same period last year.
The decrease in Free Cash Flow is mainly due to greater scheduled
debt principal payments and higher free cash flows attributed to
non-controlling interests, partly offset by the increase in cash
flows before changes in non-cash working capital items and the
realized losses on derivative financial instruments. The realized
loss on derivative financial instruments in the prior period was
related to the settlement of the Mesgi'g Ugju's'n bond forwards
contracts at the closing of the projects' financing. The
Corporation also committed to investing more to pursue growth
opportunities in new international markets, which also reduced cash
flows from operating activities.
For the trailing twelve-month period ended June 30, 2017,
the dividends on common shares declared by the Corporation amounted
to 93% of Free Cash Flow, compared with 84% for the corresponding
period last year. This negative impact is due mainly to lower free
cash flow and higher dividend payments as a result of a higher
number of common shares outstanding due to the issuance of
3,906,250 shares to three Desjardins Group-affiliated entities
under a private placement of Innergex common shares,
94,000 shares following the exercise of stock options and
377,582 shares under the Dividend Reinvestment Plan ("DRIP").
BUSINESS ACQUISITION
Acquisition of Rougemont 1-2
and Vaite
On May 24, 2017, Innergex
completed the acquisition of three wind projects in France's Bourgogne-Franche-Comté region with
an aggregate capacity of 119.5 MW. Innergex owns a 69.55% interest
in the wind farms while Desjardins Group Pension Plan owns the
remaining 30.45%.
The equity's purchase price is approximately €51.4 million (or
$76.2 million), subject to certain
adjustments. Innergex's net share of the purchase price amounted to
about €31.3 million (or $46.4
million) and was paid through funds available under its
corporate revolving credit facility. The remainder of the purchase
price was paid by Desjardins Group Pension Plan in the amount of
€20.1 million ($29.8
million).
Non-recourse debts related to the projects, which were already
in place, will amount to €174.3 million (or $258.4 million) at the end of construction and
will remain at each project level.
The aggregate annual power generation is expected to reach
278,200 MWh once the three projects are in commercial operation,
enough to power about 58,400 French households. All the electricity
produced by these wind farms will be sold under fixed-price power
purchase agreements (PPAs), with a portion of the price being
adjusted according to inflation indexes, for an initial term of 15
years, with Electricité de France
("EDF"). Innergex is expecting revenues of approximately €23.5
million (or $34.8 million) and
Adjusted EBITDA of approximately €18.2 million (or
$26.9 million) for the first twelve
months of operations.
The Rougemont-1 (36.1 MW) and
Vaite (38.9 MW) wind farms are in commercial operation. The
remaining wind project, Rougemont-2 (44.5 MW), should be fully
commissioned in the fourth quarter of 2017.
DEVELOPMENT PROJECTS
Commissioning Activities
Boulder Creek
In the second quarter, the Corporation began commercial
operation of the 25.3 MW Boulder Creek run-of-river hydroelectric
facility in British Columbia.
Construction began in October 2013.
The Commercial Operation Date (COD) Certificate delivered to BC
Hydro shows an effective commissioning date of May 16, 2017. The Boulder Creek facility's
average annual production is estimated at 92,500 MWh, enough to
power more than 8,500 households.
Construction activities
Rougemont-2
The Rougemont-2 wind project
was acquired during the second quarter of 2017. Construction was
already underway at the time of the acquisition.
As at the date of this press release, all substantial civil
works are complete, eight out of 16 wind turbines have already
reached commercial operation, and delivery and installation has
commenced on the remaining eight turbines. Full commissioning is
expected in the fourth quarter of 2017.
SUBSEQUENT EVENTS
Final Agreement to Acquire Two Wind Projects in France
On July 5, 2017, the Corporation
and Desjardins Group Pension Plan announced that a final agreement
had been signed with BayWa r.e. to purchase two wind projects in
France with a total aggregate
installed capacity of 43 MW. The electricity to be produced will be
sold under power purchase agreements at a fixed price, a portion of
which is adjusted according to inflation indexes, for an initial
term of 15 years, with Electricité de France. The equity's purchase price is
approximately €27.2 million (or $39.9
million), subject to certain adjustments. Innergex's net
share of the purchase price will amount to about €16.5 million (or
$24.2 million) and will be paid
through available funds under its corporate revolving credit
facility. Non-recourse debts related to the projects, which are
already in place, will amount to €72.0 million (or $105.7 million) and will remain at the project
level. The Corporation will reduce its exposure to exchange rate
fluctuations by entering into long-term currency hedging
instruments. Innergex will have a 69.55% interest in the wind farms
and Desjardins Group Pension Plan will own the remaining 30.45%.
The acquisition remains subject to customary closing
conditions.
DIVIDEND DECLARATION
The following dividends will be paid by the Corporation on
October 16, 2017:
|
|
|
|
|
|
Date of
announcement
|
Record
date
|
Payment
date
|
Dividend per common
share
|
Dividend per Series
A
Preferred
Share
|
Dividend per Series C
Preferred Share
|
August 3,
2017
|
September 29,
2017
|
October 16,
2017
|
$0.1650
|
$0.2255
|
$0.359375
|
On February 23, 2017, the Board of
Directors increased the annual dividend from $0.64 to $0.66 per
common share, payable quarterly.
CONFERENCE CALL REMINDER
The Corporation will hold a conference call and webcast
tomorrow, Friday, August 4, 2017,
at 10 AM (EDT). Its 2017
second quarter, mid-year review and outlook will be presented by
Michel Letellier, President and
Chief Executive Officer of Innergex, and Jean Perron, Chief
Financial Officer. Investors and financial analysts are invited to
access the conference call by dialing
1 888 231-8191 or 647 427-7450 and to
access the webcast at http://bit.ly/2sdimEC or via the
Corporation's website at www.innergex.com. Media and the public may
also access this conference call in listen-only mode. A replay of
the conference call will be available later the same day on the
Corporation's website.
About Innergex Renewable Energy Inc.
The Corporation develops, owns and operates run-of-river
hydroelectric facilities, wind farms and solar photovoltaic farms
and carries out its operations in Quebec, Ontario and British
Columbia, Canada, France
and Idaho, USA. Its portfolio of
assets currently consists of: (i) interests in 51 operating
facilities with an aggregate net installed capacity of 1,063 MW
(gross 1,758 MW), including 31 hydroelectric facilities, 19
wind farms and one solar farm; (ii) interests in one project under
construction with a net installed capacity of 31 MW (gross 45 MW),
for which a power purchase agreement has been secured; and (iii)
prospective projects with an aggregate net capacity totalling 3,560
MW (gross 3,940 MW). Innergex Renewable Energy Inc. is rated BBB-
by S&P.
The Corporation's strategy for building shareholder value is to
develop or acquire high-quality facilities that generate
sustainable cash flows and provide an attractive risk-adjusted
return on invested capital and to distribute a stable dividend.
Non-IFRS measures disclaimer
The consolidated financial statements for the three- and
six-month periods ended June 30, 2017, have been prepared in
accordance with International Financial Reporting Standards
("IFRS"). However, some measures referred to in this press release
are not recognized measures under IFRS and therefore may not be
comparable to those presented by other issuers. Innergex believes
that these indicators are important, as they provide management and
the reader with additional information about the Corporation's
production and cash generation capabilities, its ability to sustain
current dividends and dividend increases and its ability to fund
its growth. These indicators also facilitate the comparison of
results over different periods. Adjusted EBITDA, Adjusted EBITDA
Margin, Free Cash Flow and Payout Ratio are not measures recognized
by IFRS and have no standardized meaning prescribed by IFRS.
References in this document to "Adjusted EBITDA" are to revenues
less operating expenses, general and administrative expenses and
prospective project expenses.
References in this document to "Adjusted EBITDA Margin" are to
Adjusted EBITDA divided by revenues.
References to "Free Cash Flow" are to cash flows from operating
activities before changes in non-cash operating working capital
items, less maintenance capital expenditures net of proceeds from
disposals, scheduled debt principal payments, preferred share
dividends declared and the portion of Free Cash Flow attributed to
non-controlling interests, plus cash receipts by the Harrison Hydro
L. P. for the wheeling services to be provided to other facilities
owned by the Corporation over the course of their power purchase
agreement, plus or minus other elements that are not representative
of the Corporation's long-term cash generating capacity, such as
transaction costs related to realized acquisitions (which are
financed at the time of the acquisition), realized losses or gains
on derivative financial instruments used to hedge the interest rate
on project-level debt or the exchange rate on equipment
purchases.
References to "Payout Ratio" are to dividends declared on common
shares divided by Free Cash Flow.
Readers are cautioned that Adjusted EBITDA should not be
construed as an alternative to net earnings and Free Cash Flow
should not be construed as an alternative to cash flows from
operating activities, as determined in accordance with IFRS.
Forward-looking information disclaimer
In order to inform readers of the Corporation's future
prospects, this press release contains forward-looking information
within the meaning of applicable securities laws
("Forward-Looking Information"). Forward-Looking Information can
generally be identified by the use of words such as "projected",
"potential", "expect", "will", "should", "estimate", "forecasts",
"intends", or other comparable terminology that states that
certain events will or will not occur. It represents the estimates
and expectations of the Corporation relating to future results
and developments as of the date of this press release. It includes
future-oriented financial information or financial
outlook within the meaning of securities laws, such as expected
production, projected revenues, projected Adjusted EBITDA ,
projected Free Cash Flow and estimated project costs, to inform
readers of the potential financial impact of expected results, of
the expected commissioning of Development Projects, of the
potential financial impact of the acquisitions, of the
Corporation's ability to sustain current dividends and dividend
increases and of its ability to fund its growth. Such information
may not be appropriate for other purposes.
Forward-Looking Information in this press release is based on
certain key expectations and assumptions made by the Corporation.
The following table outlines Forward-Looking Information contained
in this press release, the principal assumptions used to derive
this information and the principal risks and uncertainties that
could cause actual results to differ materially from this
information.
Principal
Assumptions
|
Principal Risks and
Uncertainties
|
Expected
production
For each facility,
the Corporation determines a long-term average annual level of
electricity production ("LTA") over the expected life of the
facility, based on engineers' studies that take into consideration
a number of important factors: for hydroelectricity, the
historically observed flows of the river, the operating head, the
technology employed and the reserved aesthetic and ecological
flows; for wind energy, the historical wind and meteorological
conditions and turbine technology; and for solar energy, the
historical solar irradiation conditions, panel technology and
expected solar panel degradation. Other factors taken into account
include, without limitation, site topography, installed capacity,
energy losses, operational features and maintenance. Although
production will fluctuate from year to year, over an extended
period it should approach the estimated long-term average. On a
consolidated basis, the Corporation estimates the LTA by adding
together the expected LTA of all the facilities in operation that
it consolidates (excludes Umbata Falls and Viger-Denonville, which
are accounted for using the equity method).
|
Improper assessment
of water, wind and
sun resources and associated electricity
production
Variability in hydrology, wind regimes and
solar irradiation
Equipment failure or unexpected operations
and maintenance activity
Natural disaster
|
Estimated project
costs, expected obtainment of permits, start of construction,
work conducted and start of commercial operation for
Development Projects or Prospective Projects
For each development
project, the Corporation provides an estimate of project costs
based on its extensive experience as a developer, directly related
incremental internal costs, site acquisition costs and financing
costs, which are eventually adjusted for the projected costs
provided by the engineering, procurement and construction ("EPC")
contractor retained for the project.
The Corporation
provides indications regarding scheduling and construction progress
for its Development Projects and indications regarding its
Prospective Projects, based on its extensive experience as a
developer.
|
Performance of
counterparties, such as the
EPC contractors
Delays and cost
overruns in the design and
construction of projects
Obtainment of
permits
Equipment
supply
Interest rate
fluctuations and financing risk
Relationships with
stakeholders
Regulatory and
political risks
Higher-than-expected
inflation
Natural
disaster
|
Projected
Revenues
For each facility,
expected annual revenues are estimated by multiplying the LTA by a
price for electricity stipulated in the power purchase agreement
secured with a public utility or other creditworthy counterparty.
These agreements stipulate a base price and, in some cases, a price
adjustment depending on the month, day and hour of delivery. In
most cases, power purchase agreements also contain an annual
inflation adjustment based on a portion of the Consumer Price
Index.
|
Production levels
below the LTA caused
mainly by the risks and uncertainties
mentioned above
Unexpected seasonal
variability in the
production and delivery of electricity
Lower-than-expected
inflation rate
Changes in the
purchase price of electricity
upon renewal of a PPA
|
Projected Adjusted
EBITDA
For each facility,
the Corporation estimates annual operating earnings by subtracting
from the estimated revenues the budgeted annual operating costs,
which consist primarily of operators' salaries, insurance premiums,
operations and maintenance expenditures, property taxes and
royalties; these are predictable and relatively fixed, varying
mainly with inflation (except for maintenance
expenditures).
|
Lower revenues caused
mainly by the risks
and uncertainties mentioned above
Variability of
facility performance and
related penalties
Unexpected
maintenance expenditures
|
Projected Free
Cash Flow and intention to pay dividend quarterly
The Corporation
estimates Projected Free Cash Flow as projected cash flows from
operating activities before changes in non-cash operating working
capital items, less estimated maintenance capital expenditures net
of proceeds from disposals, scheduled debt principal payments,
preferred share dividends declared and the portion of Free Cash
Flow attributed to non-controlling interests, plus cash receipts by
the Harrison Hydro L.P. for the wheeling services to be provided to
other facilities owned by the Corporation over the course of their
power purchase agreement, plus or minus other elements that are not
representative of the Corporation's long-term cash generating
capacity, such as transaction costs related to realized
acquisitions (which are financed at the time of the acquisition),
realized losses or gains on derivative financial instruments
used to hedge the interest rate on project-level debt or the
exchange rate on equipment purchases.
The Corporation
estimates the annual dividend it intends to distribute based on the
Corporation operating results, cash flows, financial conditions,
debt covenants, long term growth prospects, solvency, test imposed
under corporate law for declaration of dividends and other relevant
factors.
|
Adjusted EBITDA below
expectations
caused mainly by the risks and uncertainties
mentioned above and by higher prospective
project expenses
Projects costs above
expectations caused
mainly by the performance of counterparties
and delays and cost overruns in the design
and construction of projects
Regulatory and
political risk
Interest rate
fluctuations and financing risk
Financial leverage and restrictive covenants
governing current and future indebtedness
Unexpected
maintenance capital
expenditures
Possibility that the
Corporation may not
declare or pay a dividend
|
The material risks and uncertainties that may cause actual
results and developments to be materially different from current
expressed Forward-Looking Information are referred to in the
Corporation's Annual Information Form in the "Risk Factors" section
and include, without limitation: the ability of the Corporation to
execute its strategy for building shareholder value; its ability to
raise additional capital and the state of capital markets;
liquidity risks related to derivative financial instruments;
variability in hydrology, wind regimes and solar irradiation;
delays and cost overruns in the design and construction of
projects; the ability to secure new power purchase agreements or
renew any power purchase agreements on equivalent terms and
conditions; uncertainty surrounding the development of new
facilities; change in governmental support to increase electricity
to be generated from renewable sources by independent power
producers; foreign market growth and development risks; sufficiency
of insurance coverage limits and exclusions; and the ability to
secure new power purchase agreements or to renew existing ones.
Although the Corporation believes that the expectations and
assumptions on which Forward-Looking Information is based are
reasonable, readers of this press release are cautioned not to rely
unduly on this Forward-Looking Information since no assurance can
be given that they will prove to be correct. The Corporation does
not undertake any obligation to update or revise any
Forward-Looking Information, whether as a result of events or
circumstances occurring after the date of this press release,
unless so required by legislation.
SOURCE Innergex Énergie Renouvelable Inc.